Page 1611 – RTO Insider

September 9, 2016

House, Senate Conferees Begin Work to Narrow Differences on Energy Bill

By Rich Heidorn Jr.

House and Senate negotiators met for the first time Thursday in an effort to reach agreement on the first broad energy bill in almost a decade.

The 31 members of the conference committee — seven senators and 24 representatives — are trying to merge the Senate’s bipartisan bill with a House bill rejected by Democrats and the target of veto threats by President Obama.

house, senate, energy bill — Conference Committee

The session was limited to opening statements from the members and no amendments or bill text were considered. But Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said 90 staffers have already been working “aggressively,” holding 30 meetings during the summer break, including a dozen in the last week. (See Senate OKs Conference on Energy Bill.)

Rep. Fred Upton (R-Mich.), chairman of the House Energy and Commerce Committee, opened the session on a conciliatory note, saying he was optimistic the conferees could find a “sweet spot” to win bipartisan support and the president’s signature.

“I’m here to listen and to work and to get things done and not take the avenue of sending a bill to the president that he would veto,” said Upton, suggesting he would like the accomplishment before he must relinquish the chairmanship next year because of term limits. “That is not on my list of things to get done.”

Upton noted that the U.S. is no longer “trying to address concerns about energy scarcity, high prices and dependence on imports. Thanks to private sector innovations leading to increased domestic oil and gas output, the script has been flipped, and Congress can now approach energy issues from a position of strength.”

Murkowski and ranking member Sen. Maria Cantwell (D-Wash.), who had steered the Senate bill to an 85-12 vote, also expressed optimism in the chances for an agreement. Murkowski is also chairing the conference committee.

The Senate passed its Energy Policy Modernization Act of 2016 (S.2012) in April, with support of all but a handful of Republicans. It authorizes increased spending on energy research, improves cybersecurity protections and encourages more efficient buildings and vehicles. It also adds taxpayer protections to the Energy Department’s loan guarantee program and streamlines federal approvals of electric transmission, pipeline, hydropower and LNG facilities. (See Energy Bill Faces Tight Calendar, Partisan Divide in House.)

The House’s Republican-drafted North American Energy Security and Infrastructure Act (H.R.8), by contrast, cleared in December with support from only three Democrats.

Getting to the finish line will require members to negotiate agreements on several flashpoints, including tougher energy efficiency standards in building codes and permanent authorization of the Land and Water Conservation Fund.

The bitterness over the one-sided House bill — evident in the remarks from some members of both parties — has tempered hopes of an agreement.

Rep. Frank Pallone (D-N.J.), the ranking member on the Energy committee, criticized the House’s “partisan” bill, which he said “would unacceptably increase energy use and costs to consumers, and would undermine our nation’s climate goals.”

“As we begin the process of working to reconcile two very different bills, it is important that any final conference report include three essential components: infrastructure investment and modernization; direct benefits for consumers, including programs that empower them to manage their energy consumption and costs; and it must be consistent with our nation’s climate goals to reduce greenhouse gas emissions.”

Sen. John Barrasso (R-Wyo.) said it was “no small accomplishment to get where we are today” and said he was hopeful the panelists would prove the “conventional wisdom” wrong by reaching agreement. But he warned Democrats not to overplay their hand, saying “do not assume this opportunity will be available next year.”

Others took their two minutes to focus on what they wanted included — or excluded — from the bill.

Rep. Rob Bishop (R-Utah) said eliminating the Senate’s energy efficiency building code language was “critically important.”

Rep. Raúl Grijalva (D-Ariz.) said the Land and Water Conservation Fund authorization is “essential.”

Rep. Lamar Smith (R-Texas), chairman of the House Committee on Science, Space, and Technology, lobbied for inclusion of House provisions reining in the Energy Department’s research and development efforts. Smith said the department should limit its work to “basic research,” an apparent reference to the controversial loan guarantees to failed companies such as Solyndra.

Rep. John Sarbanes (D-Md.) pushed back. “To not provide the Department of Energy with resources to invest in smart grid research and development would be akin to not funding the National Institutes of Health to conduct medical cures research,” he said.

Sen. Jim Risch (R-Idaho) called for increased cybersecurity protections. “The next major event is going to be a cybersecurity event,” he said. “The grid, as we all know, is a target.”

Others called for quicker approval of LNG export facilities, a provision in both bills.

Rep. David Loebsack (D-Iowa), who proudly declared that his state is now getting 30% of its electricity from wind, said he was “open-minded but … skeptical as well.”

The bill “must deliver benefits to consumers, not just [energy] producers,” he said.

September 9, 2016

NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects

By Rory D. Sweeney

In a move that elated New Jersey’s ratepayer advocates, FirstEnergy announced Thursday it is withdrawing its request for state public utility designation for its all-transmission spin-off.

FE said it made the decision because it was unlikely to win approval in time to meet the its Jan. 1 target to begin investing more than $2.5 billion in transmission infrastructure in eastern Pennsylvania and New Jersey.

“At this juncture, nearly 15 months after the original petition was filed, there appears to be no prospect of resolving this matter” in time to accommodate that schedule, the company said in a letter to Richard Mroz, president of the New Jersey Board of Public Utilities.

FE has already received approval from FERC OKs FirstEnergy’s Tx Spin-off; NJ, Pa. Approval Still Needed.)

Rate Counsel Director Stefanie Brand dismissed FE’s claims that the consolidation would reduce project costs by $135 million as “speculative.” She pointed to testimony her office submitted that argued the reorganization benefited stockholders at the expense of ratepayers.

The Rate Counsel said there were more appropriate ways to achieve the improved credit ratings that were at the heart of FE’s pitch to the BPU. As a regulated utility, JCP&L could have an excellent credit rating but has been mismanaged, Brand said.

Additionally, her office contended the proposal drastically undervalued the assets to be transferred, meaning the ratepayers who paid for them wouldn’t receive fair compensation.

Bad Precedent

The request would have also given the all-transmission company the powers of eminent domain and local-zoning pre-emption. FE’s plan originally faltered because MAIT didn’t have any distribution customers, as required for public utilities in New Jersey. In a bid to meet that requirement, FE amended its plan to give the subsidiary five customers.

Brand said that would set a bad precedent. “You can see merchant transmission companies lining up saying, ‘Oh, give me five customers; I’ll take eminent domain authority,’” Brand said in an interview.

MAIT will still consolidate the transmission assets for Met-Ed and Penelec and move forward under that name for Pennsylvania projects, FE spokesman Doug Colafella said. JCP&L will continue operating under its current structure, he said.

“We’re disappointed, but New Jersey regulators determined that a transmission company can’t be a public utility in New Jersey,” he said.

Colafella said the company will move forward with its transmission investments as planned, which are expected over the next five to 10 years. The New Jersey projects will be pursued under JCP&L’s formula rates.

Colafella wasn’t sure how the decision impacted the financials FE had originally calculated for the asset transfer to MAIT.

Brand was particularly pleased with the decision because it saved the time and expense of going to trial.

The decision was also welcomed by U.S. Rep. Frank Pallone Jr. (D-N.J.), through whose 6th District FE’s planned 10-mile Monmouth County Reliability Project would run. Pallone had previously submitted comments to the BPU on the case, in which he expressed concern about “numerous unresolved questions about the consequences of this transfer” and potential “unforeseen impacts.”

“I appreciate the work of so many of my constituents and the state Rate Counsel who stood against this transfer and its potential to hurt the quality of life in our communities,” he said in a news release.

September 8, 2016

Gov. Brown Reaffirms Commitment to Expanded CAISO

By Robert Mullin

SACRAMENTO, Calif. — Gov. Jerry Brown on Wednesday reaffirmed his commitment to an expanded CAISO, a month after asking state agencies to delay their efforts to complete enabling legislation.

Brown told the ISO’s annual stakeholder symposium that greater cooperation with balancing authority areas in neighboring states is essential to increasing the efficiency of the grid and meeting California’s ambitious renewable portfolio standard of 50% by 2030. The governor signed a bill Thursday to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030. (See California Legislature Approves Bill to Sharply Reduce GHG Emissions.)

“I think we recognize the imperative of making our electric system as efficient as it possibly can be,” Brown said. “The efficiency of a wider grid is unmistakable. And the imperative is greater efficiency, greater elegance and intelligence in the way we use and produce electricity, the way we market it and the way it goes around the system.”

caiso jerry brown — Brown © *RTO Insider*

Brown listed some of the dangers to California from climate change — including longer wildfire seasons and the potential for flooding in low-lying areas — and asked how California can work with other states “that have different perspectives” on dealing with climate change.

“That’s something I think you’re all here to figure out, because we’re not going to change differences in different states that have different needs and different experiences,” Brown said.

The governor noted that utilities in his own state at one time doubted the possibility that they could sustain a 20% RPS by 2020. But those companies are now on track to exceed that goal and are confident they will hit the 50% objective.

“But in order to get there, we need a grid that is highly sophisticated,” he said. “We need a grid that is conterminous with the technology and capability that is possible today.”

“So I hope you work all that out,” Brown added, humorously. “Make sure that those who love coal and those who love the sun can sit down and work in a totally seamless web of interconnection, interaction and happiness for all.”

Brown acknowledged the difficulty of advancing regionalization through the political process of multiple states. The governor last month postponed plans to present the legislature with a governance plan for an expanded ISO, saying there wasn’t enough time to complete the proposal before the legislative session ended Sept. 1. (See Governor Delays CAISO Regionalization Effort.)

“But the times are changing, and the technologies are forcing us to reexamine how things work,” Brown said.

September 7, 2016

UPDATED: New York Legislators Question Nuclear Subsidy

By William Opalka

Five New York City-area legislators, including the chair of the State Assembly Committee on Energy, wrote to state regulators last week questioning the ratepayer-funded nuclear power plant subsidy and requesting disclosure of the operating costs of the affected plants.

The New York Public Service Commission last month approved a Clean Energy Standard that includes a subsidy for upstate nuclear power plants. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.) In May, the commission granted Exelon’s request to keep the operating costs of its R.E. Ginna and Nine Mile Point 1 and 2 plants private (16-E-0270).

“Why should Exelon’s costs be blocked from public review when it is being given a government-directed and government-administered price subsidy?” the legislators wrote.

The zero-emission credits created by the order are expected to cost ratepayers $965 million in the first two years of their 12-year existence. Included in the subsidy is Entergy’s James A. FitzPatrick plant, which Exelon has agreed to buy. (See FitzPatrick Sale Filed with New York Regulators.)

The assemblymembers also said that Nine Mile Point 2 should be eliminated from ZEC payments and the cost of the program should be recalculated. They said the fact that Exelon refueled the plant in the spring indicates that that the facility is not financially stressed or in danger of closing.

“In the commission record, we take note that Entergy announced intentions to close FitzPatrick, and Exelon announced intentions to close R.E. Ginna and Nine Mile 1, but no formal announcement was made regarding intention to close Nine Mile 2, which produces 40% of the electricity of the four units. Without a publicly transparent cost review, and in light of the recent refueling of the unit, the payment should be removed from the commission’s order,” the letter said.

The letter also states that downstate ratepayers will be paying a disproportionate share of the subsidy — 60% — while most of the energy generated by the plants will be used upstate, closer to the plants’ locations in western New York.

The assemblymembers also said that the subsidy is based on EPA’s projected social cost of carbon, which could increase as much as 10% every two years after the first two years of the program.

The letter was signed by Energy Committee Chair Amy Paulin, who represents Westchester County; James Brennan of Brooklyn; Jeffrey Dinowitz of the Bronx; and Steve Englebright and Charles Lavine of Long Island.

In a response on Friday, PSC Chair Audrey Zibelman said there are “a number of fundamental errors” in the lawmakers’ understanding of how the power system works and the CES’ role in it.

Zibelman said the price of renewable energy credits is set by a competitive bidding process, but with few participants, ZEC prices must be set administratively. The federal social cost of carbon is a more effective mechanism and accounts for the externalities associated with fossil fuel generation, she said.

“Second, it is simply wrong for anyone to suggest that we can achieve targeted emission reductions by 2030 if we were to lose the zero-emissions attributes of the three upstate nuclear plants. Experience and fundamental economics show that the zero-emissions attributes they produce and New York needs will be replaced by adverse air emissions from existing coal and new natural gas-fired fossil units that can be dispersed throughout the state or come from out-of-state imports,” Zibelman wrote

The cost of replacing all of the nuclear generation with renewables would be more expensive than the ZECs, she added.

Finally, she disputed the assertion that the New York City area is being treated unfairly. “The CES allocates the obligation to meet the 50% renewables goals and zero-emission credits to all of the consumers of the state because all consumers will benefit from reducing carbon emissions,” Zibelman wrote.

September 7, 2016

Court Asked to Force FERC Action on Disputed ISO-NE Capacity Auction

By Rich Heidorn Jr.

WASHINGTON — A public interest group and Connecticut officials asked a federal appellate court Tuesday to force FERC to rule on the legality of ISO-NE’s eighth Forward Capacity Auction, saying the commission abdicated its responsibility by refusing to take action.

In September 2014, the commission split 2-2 over whether it should reject the results from the RTO’s auction because of unchecked market power, allowing the 2017-18 auction results to become “effective by operation of law” (ER14-1409). Under the Federal Power Act, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary.

Commissioners Tony Clark and Norman Bay called for FERC to reject the auction results, but then-Chair Cheryl LaFleur and Commissioner Philip Moeller said the commission should seek only prospective changes in the auction rules. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)

Tuesday’s arguments before a three-judge panel of the D.C. Circuit Court of Appeals focused less on the auction itself than on whether the commission’s 2-2 deadlock constituted an “action” that should be subject to judicial review. FERC contends it was an exercise of the commission’s discretion and thus not subject to second-guessing (14-1244).

Remand Sought

Scott Nelson, attorney for plaintiff Public Citizen, said the court should remand the issue to FERC for consideration of whether the auction prices were just and reasonable, as he said is required by FPA Section 205 when a rate is challenged.

He cited a statement from LaFleur contending the commission lacked authority to review the auction results, an opinion FERC’s attorneys have not embraced. LaFleur said the ISO-NE Tariff is the “filed rate” and a review of the auction prices would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”

“No one here actually defends that statement,” Nelson told the judges. “Here one of the determinative votes [on the auction results] rests on what is a clear error of law.”

The judges challenged Nelson’s arguments.

ferc iso-ne — Brown *Source: Judicial Council of California*

Judge Janice Rogers Brown told Nelson his reliance on a precedent involving the Federal Election Commission is “somewhat flawed” because the FEC’s enabling act explicitly allows judicial review of deadlocks. “Where is that in the Federal Power Act?” she asked.

FERC Solicitor Robert H. Solomon also challenged the FEC precedent. With equal numbers of Democratic and Republican appointees, Solomon said, the FEC is “designed to deadlock.” In contrast, FERC is split 3-2, with the majority representing the party in the White House.

Judge Sri Srinivasan pressed Nelson on his use of another precedent, Amador County v. Salazar, noting that the FPA allows challenges under Section 206 if the commission fails to act under Section 205.

No ‘Backstop’

“That [Section 206] remedy is not an adequate alternative,” Nelson responded, noting that while ISO-NE must prove that its rates are just and reasonable under Section 205, the burden of proof flips to the plaintiffs in Section 206. In its brief, Public Citizen noted that the D.C. Circuit has previously ruled that Section 206’s burden of proof is “practically insurmountable” for private parties challenging rates.

“206 can’t be a backstop for the agency’s failure to exercise its authority under 205,” Nelson said.

John S. Wright, an assistant Connecticut attorney general, also argued for a remand. Connecticut’s challenge to the FCA 8 results (14-1246) was consolidated with the Public Citizen complaint.

“FERC has a duty to act,” Wright said. “FERC knew the rates were subject to the exercise of market power.”

The auction saw total capacity costs for 2017/18 rise to $3.05 billion — almost double the previous high — as the region’s capacity shifted from an expected surplus to a deficiency of more than 1,000 MW. The shortfall was because of plant retirements, including that of the 1,488-MW Brayton Point station in Massachusetts.

iso-ne forward capacity auction, ferc — Brayton Point *Source: Wikipedia*

Wright said ISO-NE erred in the auction by treating capacity importers as “new” supply and not subjecting their bids to review, unlike existing resources. New resources in the Maine, Connecticut and Rest of Pool capacity zones were paid $15/kW-month, while existing resources in those zones received an administrative price of $7.025/kW-month.

However, FERC said its Office of Enforcement investigated Brayton Point’s retirement and determined it was justified.

In addition to announcing their deadlock in September 2014, the commissioners voted unanimously to open a new docket (EL14-99) calling for a Section 206 proceeding over the RTO’s process for reviewing importers’ offers and mitigating their market power. The commission approved Tariff changes addressing those concerns in December 2014 (ER15-117). (See FERC OKs Tightened ISO-NE Screening on Capacity Imports.)

‘Non-Order’

FERC’s Solomon said there is nothing for the court to review because the “commission made no decision.”

Statements issued by LaFleur and the other three commissioners were not official orders and thus not reviewable, he said. “What matters is whether anything has been articulated by the agency as an institutional body.”

The commission’s notice, he said, was a “non-order.”

Srinavasan Source: US Department of Justice — Srinavasan *Source: US Department of Justice*

Srinivasan asked how often FERC has allowed rates to go into effect “by operation of law.”

“This is extremely rare, your honor,” Solomon responded, saying the commission has identified only six such instances in 80 years.

As evidence of the commission’s discretionary authority, Solomon quoted from subsections C, D and E of Section 205, which repeatedly use the word “may.”

Supporting FERC’s position Tuesday was Paul A. Mezzina, attorney for intervenor Electric Power Supply Association. Mezzina said that when market rules are followed, the results are “presumptively just and reasonable.”

Judge Brown pointed out that the settlement that led to the creation of ISO-NE’s capacity market says the commission “will” review the auction results.

But Mezzina said the settlement didn’t “take away any of the commission’s discretion to determine what the review consists of.” He said the commission has “broad discretion” and “no unequivocal obligation to act.”

FERC Chief of Staff Larry Gasteiger was among the FERC officials in the audience for the arguments. Also in attendance were representatives of some of the other intervenors supporting FERC: NRG Power Marketing, H.Q. Energy Services, Calpine, the New England Power Generators Association and the New England Power Pool Participants Committee.

Ruling

The FCA 8 rates will take effect June 1, 2017.

If the court rules that it has jurisdiction to review the commission’s inaction, it will have to decide whether the FPA allows a protested rate filing to go into effect when the commission cannot issue an order by majority vote.

Nelson said after the hearing he expected a ruling by March. Solomon said it could be as long as a year.

Were the issue to be remanded to FERC, Moeller, who left the commission last year, and Clark, who is stepping down this month, would have no role.

Following Clark’s departure, the commission will be short two members, with only LaFleur, Bay and Colette Honorable, who joined in January 2015.

Meanwhile, the capacity dispute has attracted the attention of the New England congressional delegation, which won House approval in March of a bill that would amend the FPA to allow court review of any inaction by the commission that allows a rate change to go into effect (HR 2984).

The Senate has not acted on the bill.

September 7, 2016

Enbridge-Spectra Deal Would Create No. 1 Energy Infrastructure Co. in No. America

By Ted Caddell

Canadian pipeline giant Enbridge is buying American pipeline company Spectra Energy in a $28 billion deal that will create North America’s largest energy infrastructure company.

Enbridge, which specializes in pipelines moving crude oil, will be moving into the natural gas transportation business with the all-stock transaction. Enbridge said in its news release that the acquisition will allow it to diversify both regionally and operationally.

The deal will give Enbridge a continent-wide system of natural gas, gas-liquid and crude oil pipelines, as well as terminals, gas distribution operations and a stable of wind, solar and geothermal generation.

Combined Enbridge and Spectra Energy map — *Source: Enbridge*

“Over the last two years, we’ve been focused on identifying opportunities that would extend and diversify our asset base and sources of growth beyond 2019,” Enbridge CEO Al Monaco said. “We are accomplishing that goal by combining with the premier natural gas infrastructure company to create a true North American and global energy infrastructure leader.”

11.5% Premium

Monaco will remain at the helm of the combined companies. Spectra CEO Greg Ebel will move over to serve as non-executive chairman of the Enbridge board. “The combination of Enbridge and Spectra Energy creates what we believe will be the best, most diversified energy infrastructure company in North America, if not the world,” Ebel said.

Spectra shareholders will get Enbridge shares valued at about $40.33 each, a premium of about 11.5% from Spectra’s closing price Friday. At closing, which the companies expect to be completed by the first quarter of 2017, Enbridge shareholders will hold about 57% of the new company, and Spectra shareholders will hold 43%. Headquarters of the new company will be in Calgary.

The deal comes at a time when natural gas producers and transporters are struggling with low commodity prices even as they are constructing large numbers of new pipelines and extending older ones to accommodate the increased production from shale gas plays. Existing pipelines are especially valuable, considering the costs and regulatory hurdles facing new pipeline construction.

Setbacks

Both Spectra and Enbridge have recently had setbacks in pipeline construction projects. The Massachusetts Supreme Judicial Court ruled that power utilities that would become customers of the Spectra-proposed Access Northeast in New York and New England cannot pass on additional construction costs to customers. In June, a Canadian court blocked Enbridge’s proposed Northern Gateway oil pipeline that was to run from Alberta — home of Canada’s tar sands fields — to terminals on the Pacific Coast.

Enbridge and Spectra — Enbridge’s 450-acre Superior Terminal at Superior, Wisconsin *Source: Enbridge*

And just days ago, Enbridge announced it was suspending pursuit of regulatory approval for its proposed $2.6 billion Sandpiper pipeline in Minnesota, citing a drop in projected crude oil production in South Dakota and shifting of customer capacity needs to the Dakota Access line.

The Dakota project is garnering notice because of protests from the Standing Rock Sioux Tribe, which is blocking access to a construction site near the border between the Dakotas. The tribe has filed a lawsuit against the U.S. Army Corps of Engineers for approving the pipeline crossing the Missouri River upstream from the tribe’s reservation. The suit claims that the pipeline threatens both the tribe’s drinking water source and its sacred lands.

Fires — possibly arson — caused an estimated $1 million in damage to Dakota Access construction equipment in Iowa last month.

Spectra is not Enbridge’s first acquisition of the summer. Last month, it announced that it and Marathon Petroleum were investing in Dakota Access, with the two companies acquiring 49% equity interest in the Bakken Pipeline System from Energy Transfer and Sunoco Logistics. Enbridge put up $1.5 billion for its 37% share of the 1,168-mile, $3.78 billion pipeline, which is to run from North Dakota to terminals in Illinois.

September 5, 2016

ERCOT Expects Adequate Generation for Fall, Winter

By Tom Kleckner

ERCOT’s latest resource adequacy assessments indicate it has 25,000 to 30,000 MW of spare generating capacity for the fall and winter.

ERCOT Control Room (ERCOT) - fall winter ercot generating capacity — ERCOT’s control rom *Source: ERCOT*

The Texas grid operator’s final Seasonal Assessment of Resource Adequacy (SARA) for October and November includes more than 82,000 MW of capacity, more than enough to meet a projected peak demand of about 54,400 MW.

The preliminary winter SARA report is similarly rosy, with more than 81,000 MW of capacity available to meet a forecasted record peak demand just under 59,000 MW. The winter demand record of 57,265 MW was set during February 2011’s record cold.

ERCOT, which operates 90% of the Texas grid, said four gas-fired combustion turbine units and three wind projects have begun operating since its preliminary fall SARA, adding nearly 900 MW of capacity. Three of the gas units are switchable resources and can connect to either ERCOT’s or SPP’s grids. The fall forecast assumes 13,700 to 19,000 MW of planned and unplanned outages.

Another 1,200 MW of new winter-rated capacity is expected to be in service for the winter season (December-February). The final winter SARA report will be released in November.

— Tom Kleckner

September 5, 2016

Monitor OKs PJM Auction; Says Problems Remain Despite CP

By Rich Heidorn Jr.

PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.

The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”

PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.

pjm market monitor capacity auction capacity performance — Bowring © *RTO Insider*

The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).

The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)

But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”

In addition, the Monitor recommended:

All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
Extending the MOPR to existing units in addition to new units.
Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”

September 5, 2016

FERC Rejects Capacity Release Exemption for NE Gas Generators

By William Opalka

FERC on Wednesday rejected Algonquin Gas Transmission’s request to exempt gas-fired generators from competitive bidding under capacity release rules, another blow to those seeking to increase New England’s gas infrastructure (RP16-618).

Maine PUC, pipeline contracts, ferc, natural gas, Algonquin Gas Transmission, capacity release exemption — *Photo credit: Steve Oehlenschlager*

The proposal to amend Algonquin’s tariff was an offshoot of the company’s proposed Access Northeast pipeline. Electric distribution companies Eversource Energy and National Grid — which are partnering with Algonquin on the pipeline — sought the exemption to ensure the capacity they purchased would be used to fuel gas-fired generators.

The EDCs hoped to release capacity to gas generators as prearranged “replacement” shippers. FERC rules allow such preferences as long as the replacement shipper matches the highest bid submitted by any other bidder. The proposal would have limited that bidding to gas-fired generators, excluding those who might value the fuel more for winter heating.

FERC held a technical conference on the matter in the spring. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.)

The proposal was opposed by numerous merchant generators, including NextEra Energy, Exelon and Calpine, which said they had found cheaper alternatives to ensure fuel supplies under ISO-NE’s Pay-for-Performance capacity incentives, including installation of dual-fuel capacity and contracts with natural gas marketers and LNG suppliers.

“Merchant generators are not asking you for this capacity, and you need to ask yourself why,” Calpine told FERC. The company estimated firm capacity would cost it $25 million annually, or half a billion dollars over a 20-year commitment. It said it could guarantee the same level of service by investing $50 million in a fuel oil tank.

Other opponents argued that the proposal was premature because no state had approved a state-regulated electric reliability program.

“Neither Eversource nor National Grid provided a persuasive explanation for why the ability to release capacity to a prearranged replacement shipper under our existing regulations is not sufficient to meet their needs,” FERC ruled. “Moreover, neither party sufficiently explained why a generator that needed the capacity to obtain the natural gas supplies necessary to generate electricity during a period when Algonquin’s capacity is constrained would not match a higher bid.”

However, the commission said its ruling was “without prejudice to Algonquin developing other more targeted, justified proposals for consideration.”

The commission also granted Algonquin’s request to exempt from bidding an EDC’s capacity release to third parties managing capacity on an EDC’s behalf.

“By permitting capacity holders to use third-party experts to manage their natural gas supply arrangements and their pipeline capacity, [asset management arrangements] provide for lower gas supply costs and more efficient use of the pipeline grid,” the commission said. A compliance filing on this proposal is due in 30 days.

Access Northeast suffered a setback in August when the Massachusetts Supreme Judicial Court overruled state regulators’ order to allow construction costs be assessed to electricity ratepayers. Soon after the ruling, the EDCs withdrew their proposed contracts that were pending before the Massachusetts Department of Public Utilities. (See Eversource, National Grid Withdraw Requests to Bill for Pipeline.)

Access Northeast Complaint Dismissed

In a related case, FERC dismissed a complaint filed by electric generators seeking to block EDC contracts with pipeline owners as premature (EL16-93).

Public Service Enterprise Group and NextEra said the contracts would render the power markets discriminatory and suppress power prices. (See Generation Owners Seek to Block EDC-Pipeline Deals.)

“The circumstances giving rise to the complaint are in a state of flux and the commission does not have before it the concrete facts necessary to determine whether the tariff will be unjust and unreasonable. Several critical project elements of the individual states’ electric reliability programs are undetermined at this time,” FERC wrote.

The commission cited the Massachusetts court ruling, its concurrent order on capacity releases and its pending ruling on Access Northeast, which is expected in the fourth quarter.

September 5, 2016

EIM Governing Body Convenes First Meeting, Selects Leadership

By Robert Mullin

The newly established Western Energy Imbalance Market (EIM) governing body kicked off its first meeting last week by electing its leadership.

CAISO’s Board of Governors appointed the five-member body in June, selecting one each from five industry sectors: EIM entities, ISO-participating transmission owners, power suppliers and marketers, publicly owned utilities and state regulators. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.)

Kristine Schmidt, president of Dallas-based Swan Consulting, was selected to serve as the body’s chair. A former vice president at ITC Holdings and director at Xcel Energy, Schmidt has more than 30 years’ experience in the energy sector. She also worked as an adviser to former FERC Commissioner Nora Brownell.

Howe and Schmidt - Energy imbalance market (eim) leader meeting — The EIM Governing Body selected Kristine Schmidt and Doug Howe as its chair and vice-chair, respectively.

Doug Howe, an independent consultant and Ph.D. in mathematics, was chosen as vice chair. Howe has authored or co-authored more than 30 papers and presentations covering industry topics such as energy efficiency in the European Union and utility regulation in the U.K. He previously held an executive position with GPU Inc., which was acquired by FirstEnergy in 2001.

Carl Linvill, a member of the governing body, praised Schmidt for her “equanimity” and also expressed support for the wider Western regional representation that Howe — a New Mexico resident and former state regulator — will provide.

“We still have a lot to figure out and learn,” Linvill said. “Figuring out how to establish a regional presence really is emboldened and enabled by these two positions.”

“On behalf of the ISO, we want to give you our immense thanks for being willing to serve on this body,” CAISO CEO Steve Berberich said. “We consider the EIM as a critical attribute and will continue to support it for as long as necessary.”

A decade ago, Schmidt noted, nobody in the industry would’ve believed the region would have an EIM.

“We’re now seeing a regional market take shape in the West,” Schmidt said. “We’re hitting the ground running.”

Stakeholder Coordination

The governing body’s inaugural meeting included a set of briefings by EIM stakeholders and ISO staff to acquaint members with key structures affecting the market.

“There’s a lot of interest in what you’ll be doing,” said Tony Braun, an industry consultant who chairs the Regional Issues Forum, a loosely structured stakeholder group created by CAISO to foster broad regional discussion about EIM-related issues.

While the forum’s role “has not been concretely laid out,” the group’s first two meetings have been well attended, indicating a high level of interest in the EIM’s activities, Braun said.

The two most significant issues for forum participants: the bidding of external resources at the EIM’s interties and the impact of California’s greenhouse gas regulations on the market. (See related story, CAISO Kicks off Effort to Track GHGs Under Regionalization.)

Braun proposed that future meetings of the forum be coordinated with those of the EIM’s governing body and its state regulators’ group to improve collaboration and reduce participants’ travel for meetings.

“We’d love to hear how we can shape our processes to help you do your jobs,” Braun said.

Governing body members expressed appreciation for the work of the forum.

“The stakeholder-driven nature of the [forum] is probably something that is both difficult and necessary,” said governing body member Valerie Fong. “I found that the way [the meetings are] being run is very open.”

Schmidt called the meetings “extremely helpful.”

“We’re trying to do everything we can do to mitigate some of the travel issues,” she added.

Regulatory Collaboration

Ann Rendahl, chair of the EIM’s body of state regulators, sketched out the role of her group for the new governing body.

“Our purpose is to ensure that state regulators that aren’t involved in this market understand what is going on in EIM,” said Rendahl, a member of the Washington Utilities and Transportation Commission.

The group provides a forum for regulators to learn about EIM and CAISO developments that might be relevant to their jurisdictional responsibilities. While it can take a common position in CAISO and EIM stakeholder processes, individual regulatory commissions are not restricted from taking any position before FERC or the ISO board on EIM-related matters.

The regulators’ group is also charged with monitoring EIM governing body action items and selecting a voting member for the body’s nominating committee.

Rendahl emphasized the need for her group to closely coordinate its activities with that of the governing body. “We want to not just monitor, but work with the governing body,” she said.

ISO Process Basics

Governing body members received a briefing about CAISO’s stakeholder process from Brad Cooper, ISO manager of market design and regulatory policy.

Cooper explained the stakeholder process the ISO uses each fall to develop a “roadmap” of planned policy developments, including EIM initiatives. The ISO last year drew from a catalog of 49 potential initiatives, selecting only 10 because of staff constraints.

“We can’t develop everything in the catalog,” Cooper said.

A final roadmap is presented to the CAISO board — and, in the future, the EIM governing body — at the beginning of each year. The ISO informs stakeholders of any changes to the roadmap through its Market Performance and Planning Forum.

“The roadmap isn’t set in stone,” Cooper said. “For instance, we had the Aliso Canyon issue come up” earlier this year, forcing a modification of the roadmap. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)

When developing the roadmap, ISO staff divide initiatives into four categories, including initiatives already in progress, policy changes mandated by FERC, non-discretionary efforts related to reliability or market efficiency, and discretionary initiatives.

For the last category, ISO staff and stakeholders together prioritize potential initiatives according to benefits and feasibility.

“If something could provide great benefits and is relatively trivial to do, that would get priority,” Cooper said.

Cooper acknowledged that CAISO’s policy process is driven more by staff than by stakeholders — and said the ISO prefers it that way.

“We realize that we made a commitment to look at other [stakeholder] processes [to implement under] regionalization, but we think our stakeholder process really allows us to quickly evolve policies,” Cooper said, adding that he didn’t think a project such as the EIM could’ve been developed under a stakeholder-led model.

“The ISO really tries to take a balanced view of our proposed policy,” Cooper said, contending that the ISO’s process does not factor in specific stakeholder interests, avoids “contentious voting structures,” and prevents bias or brokered policy decisions — allowing the ISO to focus on grid reliability.

Still, Cooper emphasized that “stakeholders are involved every step of the way,” including through “working group” meetings that focus on specific initiatives.

“We have a lot of open interaction that may not be possible with more formal stakeholder processes,” Cooper said. “This allows us to really interact with our stakeholders and get their input.”